In drilling a borehole in the earth, such as for the recovery of hydrocarbons or for other applications, it is conventional practice to connect a drill bit on the lower end of an assembly of drill pipe sections which are connected end-to-end so as to form a "drill string." The drill string is rotated by apparatus that is positioned on a drilling platform located at the surface of the borehole. Such apparatus turns the bit and advances it downwardly, causing the bit to cut through the formation material by either abrasion, fracturing, or shearing action, or through a combination of all cutting methods. While the bit is rotated, drilling fluid is pumped through the drill string and directed out of the drill bit through nozzles that are positioned in the bit face. The drilling fluid is provided to cool the bit and to flush cuttings away from the cutting structure of the bit. The drilling fluid and cuttings are forced from the bottom of the borehole to the surface through the annulus that is formed between the drill string and the borehole.
Many different types of drill bits and bit cutting structures have been developed and found useful in drilling such boreholes. Such bits include fixed cutter bits and roller cone bits. The types of cutting structures include milled tooth bits, tungsten carbide insert ("TCI") bits, PDC bits, and natural diamond bits. The selection of the appropriate bit and cutting structure for a given application depends upon many factors. One of the most important of these factors is the type of formation that is to be drilled, and more particularly, the hardness of the formation that will be encountered. Another important consideration is the range of hardnesses that will be encountered when drilling through layers of differing formation hardness.
Depending upon formation hardness, certain combinations of the above-described bit types and cutting structures will work more efficiently and effectively against the formation than others. For example, a milled tooth bit generally drills relatively quickly and effectively in soft formations, such as those typically encountered at shallow depths. By contrast, milled tooth bits are relatively ineffective in hard rock formations as may be encountered at greater depths. For drilling through such hard formations, roller cone bits having TCI cutting structures have proven to be very effective. For certain hard formations, fixed cutter bits having a natural diamond cutting structure provide the best combination of penetration rate and durability. In formations of soft and medium hardness, fixed cutter bits having a PDC cutting structure have been employed with varying degrees of success.
The cost of drilling a borehole is proportional to the length of time it takes to drill the borehole to the desired depth and location. The drilling time, in turn, is greatly affected by the number of times the drill bit must be changed, in order to reach the targeted formation. This is the case because each time the bit is changed, the entire drill string--which may be miles long--must be retrieved from the borehole section by section. Once the drill string has been retrieved and the new bit installed, the bit must be lowered to the bottom of the borehole on the drill string which must be reconstructed again, section by section. As is thus obvious, this process, known as a "trip" of the drill string, requires considerable time, effort and expense. Accordingly, it is always desirable to employ drill bits which will drill faster and longer and which are usable over a wider range of differing formation hardnesses.
The length of time that a drill bit may be employed before the drill string must be tripped and the bit changed depends upon the bit's rate of penetration ("ROP"), as well as its durability or ability to maintain a high or acceptable ROP. Additionally, a desirable characteristic of the bit is that it be "stable" and resist vibration. The most severe type or mode of vibration is "whirl," which is a term used to describe the phenomenon where a drill bit rotates at the bottom of the borehole about a rotational axis that is offset from the geometric center of the drill bit. Such whirling subjects the cutting elements on the bit to increased loading, which causes the premature wearing or destruction of the cutting elements and a loss of penetration rate.
In recent years, the PDC bit has become an industry standard for cutting formations of soft and medium hardnesses. The cutter elements used in such bits are formed of extremely hard materials and include a layer of thermally stable polycrystalline diamond material. In the typical PDC bit, each cutter dement or assembly comprises an elongate and generally cylindrical support member which is received and secured in a pocket formed in the surface of the bit body. A disk or tablet-shaped, preformed cutting element having a thin, hard cutting layer of polycrystalline diamond is bonded to the exposed end of the support member, which is typically formed of tungsten carbide. Although such cutter elements historically were round in cross section and included a disk shaped PDC layer forming the cutting face of the dement, improvements in manufacturing techniques have made it possible to provide cutter elements having PDC layers formed in other shapes as well.
A common arrangement of the PDC cutting elements was at one time to place them in a spiral configuration. More specifically, the cutter elements were placed at selected radial positions with respect to the central axis of the bit, with each element being placed at a slightly more remote radial position than the preceding element. So positioned, the path of all but the center-most elements partly overlapped the path of movement of a preceding cutter element as the bit was rotated. Thus, each element would remove a lesser volume of material than would be the case if it were radially positioned so that no overlapping occurred, or occurred to a lesser extent, because the leading cutter element would already have removed some formation material from the path being traveled by the following cutter element. Using this arrangement of cutters, each cutter tended to remove a comparatively small amount of material from the formation during each revolution, and was subjected to substantially the same loading as the other cutter elements on the bit face.
Although the spiral arrangement was once widely employed, this arrangement of cutter elements was found to wear in a manner to cause the bit to assume a cutting profile that presented a relatively flat and single continuous cutting edge from one element to the next. Not only did this decrease the ROP that the bit could provide, it but also increased the likelihood of bit vibration. Both of these conditions are undesirable. A low ROP increases drilling time and cost, and may necessitate a costly trip of the drill string in order to replace the dull bit with a new bit. Excessive bit vibration will itself dull the bit or may damage the bit to an extent that a premature trip of the drill string becomes necessary.
Thus, in addition to providing a bit capable of drilling effectively at desirable ROP's through a variety of formation hardnesses, preventing bit vibration and maintaining stability of PDC bits has long been a desirable goal, but one which has not always been achieved. Bit vibration may occur in any type of formation, but is most detrimental in the harder formations. As described above, the cutter elements in many prior art PDC bits were positioned in a spiral relationship which, as drilling progressed, wore in a manner which caused the ROP to decrease and which also increased the likelihood of bit vibration.
There have been a number of designs proposed for PDC cutting structures that were meant to provide a PDC bit capable of drilling through a variety of formation hardnesses at effective ROP's and with acceptable bit life or durability. For example, U.S. Pat. No. 5,033,560 (Sawyer et al.) describes a PDC bit having mixed sizes of PDC cutter elements which are arranged in an attempt to provide improved ROP while maintaining bit durability. The '560 patent is silent as to the ability of the bit to resist vibration and remain stable. Similarly, U.S. Pat. No. 5,222,566 (Taylor et at.) describes a drill bit which employs PDC cutter elements of differing sizes, with the larger size elements employed in a first group of cutters, and the smaller size employed in a second group. This design, however, suffers from the fact that the cutter elements do not share the cutting load equally. Instead, the blade on which the larger sized cutters are grouped is loaded to a greater degree than the blade with the smaller cutter elements. This could lead to blade failure. U.S. Pat. No. Re 33,757 (Weaver) describes still another cutting structure having a first row of relatively sharp, closely-spaced cutter elements, and a following row of widely-spaced, blunt or rounded cutter elements for dislodging the formation material between the kerfs or grooves that are formed by the sharp cutters. While this design was intended to enhance drilling performance, the bit includes no features directed toward stabilizing the bit once wear has commenced. Further, the bit's cutting structure has been found to limit the bit's application to relatively brittle formations.
Separately, other attempts have been made at solving bit vibration and increasing stability. For example, U.S. Pat. No. Re 34,435 (Warren et al.) describes a bit intended to resist vibration that includes a set of cutters which are disposed at an equal radius from the center of the bit and which extend further from the bit face than the other cutters on the bit. According to that patent, the set of cutters extending furthest from the bit face are provided so as to cut a circular groove within the formation. By design, the extending cutters ride in the groove which tends to stabilize the bit. Similarly, U.S. Pat. No. 5,265,685 (Keith et at.) discloses a PDC bit that is designed to cut a series of grooves in the formation such that the resulting ridges formed between each of the concentric grooves tend to stabilize the bit. U.S. Pat. Nos. Re 34,435 and 5,265,685 both disclose using the same sized cutter elements. U.S. Pat. No. 5,238,075 (Keith et at.) also describes a PDC bit having a cutter element arrangement which employs cutter elements of different sizes and which, in part, was hoped to provide greater stabilization. However, many of these designs aimed at minimizing vibration required that drilling be conducted with an increased weight-on-bit ("WOB") as compared with bits of earlier designs. Drilling with an increased or heavy WOB has serious consequences and is avoided whenever possible. Increasing the WOB is accomplished by adding additional heavy drill collars to the drill string. This additional weight increases the stress and strain on all drill string components, causes stabilizers to wear more quickly and to work less efficiently, and increases the hydraulic pressure drop in the drill string, requiring the use of higher capacity (and typically higher cost) pumps for circulating the drilling fluid.
Thus, despite attempts and certain advances made in the art, there remains a need for a fixed cutter bit having an improved cutter arrangement which will permit the bit to drill effectively at economical ROP's and, ideally, to drill in formations having a hardness greater than that in which conventional PDC bits can be employed. More specifically, there is a need for a PDC bit which can drill in soft, medium, medium hard and even in some hard formations while maintaining an aggressive cutter profile so as to maintain acceptable ROP's for acceptable lengths of time and thereby lower the drilling costs presently experienced in the industry. Such a bit should also provide an increased measure of stability as wear occurs on the cutting structure of the bit so as to resist bit vibration. Ideally, the increased stability of the bit should be achieved without having to employ substantial additional WOB and suffering from the costly consequences which arise from drilling with such extra weight.